7.2 Sulfidation in H2-Free Environments

7.2 Sulfidation in H2-Free Environments

Sulfidation (also designated as High-Temperature Sulfidic Corrosion) in hydrogen-free ($\text{H}_2$-free) hydrocarbon environments is the high-temperature chemical reaction between metallic iron, low-alloy steels, or stainless steels and naturally occurring sulfur compounds present in crude oil and refined fractions. Documented under API RP 571 Section 3.61, sulfidation is one of the most prevalent and historically significant damage mechanisms in petroleum refineries.

Sulfidation operates across crude distillation units (CDUs), vacuum distillation units (VDUs), delayed cokers, visbreakers, and fluid catalytic cracking (FCC) recovery sections. The degradation occurs in hot, non-aqueous hydrocarbon liquids and vapors in the complete absence of hydrogen gas. In $\text{H}_2$-free systems, sulfidation initiates at temperatures above 500 °F (260 °C) and accelerates aggressively above 550 °F (288 °C), resulting in uniform circumferential metal loss that can lead to catastrophic, full-bore piping rupture if remaining wall thickness is not meticulously managed.

                         [ Hot Hydrocarbon Stream: H2-Free, T > 500 °F ]
                         Reactive Sulfur Compounds (Mercaptans, Disulfides, S8)
                                                    |
                                                    v
                  +-------------------------------------------------------------+
                  | Multi-Layer Iron Sulfide Scale (Pyrrhotite: Fe1-xS)         |
                  | Porous, Friable, Black/Dark Gray, Easily Delaminates        |
                  +-------------------------------------------------------------+
                                                    ^
                                                    | Fe2+ Cation Migration Outward
                  +-------------------------------------------------------------+
                  | Carbon Steel or Cr-Mo Low-Alloy Substrate                   |
                  | (Uniform Circumferential Wall Thinning)                     |
                  +-------------------------------------------------------------+

Chemical Reaction Mechanisms and Sulfide Scale Formation

Unlike aqueous corrosion, high-temperature sulfidation does not require liquid water or ionic electrolytes. It is a direct high-temperature heterogeneous gas/liquid-solid metallurgical reaction. Sulfur atoms react directly with the iron lattice to form iron sulfide (FeS), predominantly in the crystallographic form of pyrrhotite ($\text{Fe}_{1-x}\text{S}$):

1. Direct Reaction with Reactive Elemental Sulfur: $\text{Fe} + \text{S}_{(\text{reactive})} \longrightarrow \text{FeS}$

2. Reaction with Aliphatic Mercaptans (Thiols): $\text{Fe} + \text{R-SH} \longrightarrow \text{FeS} + \text{R-H}$

3. Reaction with Disulfides and Polysulfides: $\text{Fe} + \text{R-S-S-R} \longrightarrow \text{FeS} + \text{R-S-R}$

Pyrrhotite ($\text{Fe}_{1-x}\text{S}$) is a metal-deficient, p-type semiconductor with substantial iron cation vacancies in its hexagonal lattice. The corrosion rate is controlled by the outward solid-state diffusion of ferrous cations ($\text{Fe}^{2+}$) through these vacancies toward the outer scale surface, where they combine with incoming sulfur species. Because the pyrrhotite scale is naturally porous, friable, and mechanically weak, it provides only partial diffusion resistance compared to oxide scales.

Reactive Sulfur vs. Total Sulfur: The Critical Chemical Distinction

A core, heavily emphasized concept in API RP 571 Section 3.61 is that Total Sulfur Content does NOT correlate directly with sulfidation corrosivity in H2-free environments.

Standard refinery laboratory assays measure Total Sulfur (via X-ray fluorescence per ASTM D4294 or combustion per ASTM D2622). Total sulfur captures every sulfur atom present in the oil, irrespective of its chemical bonding. However, organic sulfur compounds in crude oil fall into distinct chemical classifications with vastly different thermal stability and reactivity:

The Heavy Crude Paradox

In heavy, sour crude oils (such as Canadian bitumen or Venezuelan extra-heavy crudes), total sulfur may exceed 3.0 wt% to 5.0 wt%. However, 70% to 85% of that sulfur is locked within polycyclic aromatic rings (dibenzothiophenes and alkyl-substituted benzothiophenes). In an atmospheric crude tower operating at 680 °F without hydrogen, these ring structures remain intact and pass into the bottoms stream without corroding the steel.

Conversely, a lighter crude with only 0.8 wt% total sulfur that happens to be exceptionally rich in light aliphatic mercaptans and elemental sulfur will cause severe, rapid sulfidation attack. Therefore, assessing sulfidation risk based on total sulfur alone leads to dangerous design and operational errors.

Temperature Profile and Kinetics of H2-Free Sulfidation

High-temperature sulfidation in $\text{H}_2$-free environments is bounded by precise thermal thresholds:

The McConomy and Modified McConomy Curves

To predict corrosion rates in $\text{H}_2$-free sulfidation service, the refining industry relies on the Modified McConomy Curves, originally developed by H.F. McConomy in 1963 and subsequently revised by API and NACE to reflect decades of empirical refinery operating data.

Structure of the Modified McConomy Correlation

The modified McConomy correlation establishes a baseline corrosion rate for carbon steel exposed to a crude hydrocarbon stream containing 0.6 wt% total sulfur, plotted as a function of temperature between 500 °F and 800 °F (260 °C and 427 °C).

  Corrosion Rate (mpy)
   60 |                                                  CS Baseline (0.6% S)
   50 |                                            * * *
   40 |                                      * * *
   30 |                                * * *
   20 |                          * * *           [ 5Cr-0.5Mo: lower curve ]
   10 |                    * * *                 [ 9Cr-1Mo: lower still   ]
    0 +--------------* * *-----------------------[ 300 SS: highly resistant]
     500°F         600°F         700°F         800°F
                          Temperature (°F)

To determine the actual predicted corrosion rate for a specific alloy and process stream, two adjustment factors are applied:

$\text{Corrosion Rate} = \text{Base Rate}_{(\text{Temp})} \times F_{\text{Sulfur}} \times F_{\text{Alloy}}$

1. Sulfur Content Correction: Accounts for sulfur contents that differ from the curve's 0.6 wt% baseline, read from the companion sulfur-correction curve.
2. Alloy Curves: Separate curves show the lower rates of chromium-bearing alloys, from low-chromium steels through 12Cr and 18Cr-8Ni stainless steel.

Use the published curves (API RP 939-C and RP 571 reproduce them) for actual values; the numbers in this section are for orientation only.

Chromium Alloying Effects: The Progressive Resistance Pathway

In $\text{H}_2$-free sulfidation, adding chromium to steel stabilizes the crystal lattice by incorporating chromium into the sulfide scale, forming complex $(\text{Fe,Cr})_x\text{S}_y$ spinel structures that drastically reduce cation vacancy concentration and cation mobility.

API RP 571 states that resistance to sulfidation increases with chromium content and that 300 series SS are highly resistant. Read actual values from the curves rather than memorizing single multipliers.

The Low-Silicon Carbon Steel Anomaly (API RP 571 & API 939-C)

One of the most critical safety alerts and heavily tested concepts in refinery inspection is the Silicon Effect in Carbon Steel, governed in detail by API Recommended Practice 939-C (Guidelines for Avoiding Sulfidation Corrosion Failures in Oil Refineries).

The Discovery and Mechanism of Low-Silicon Accelerated Attack

Historically, carbon steel pipe specifications (such as ASTM A53 Grade B or vintage ASTM A106 Grade B) did not mandate a strict minimum silicon content. In steelmaking, silicon is added primarily as a deoxidizer ("killing" agent) to remove dissolved oxygen prior to casting. Steels manufactured via semi-killed or rimmed practices often contained residual silicon levels below 0.10 wt%, sometimes as low as 0.01 wt% to 0.05 wt%.

Extensive laboratory investigations and catastrophic refinery failures (most notably the 2012 Chevron Richmond refinery crude unit fire, investigated by the U.S. Chemical Safety Board) established that:

1. Carbon steels with Si < 0.10 wt% can corrode significantly faster than silicon-killed carbon steels (typically 0.10 wt% Si or more) at identical temperatures and sulfur concentrations; reported multiples vary widely.
2. Mechanism: Silicon atoms segregate near the metal-scale interface, facilitating the development of a compact, highly adherent, iron silicate or silicon-enriched subscale. This barrier layer significantly restricts the outward diffusion of $\text{Fe}^{2+}$ cations. In low-silicon steels, this subscale cannot form; the resulting pyrrhotite scale is extremely porous, poorly adhered, defect-rich, and prone to continuous micro-delamination, allowing unrestricted cation migration.

Affected Equipment, Damage Morphology, and Inspection Protocols

1. High-Risk Refinery Locations

• Crude Distillation Units (CDU): Atmospheric furnace radiant tubes, furnace crossover piping, atmospheric transfer line, atmospheric column flash zone internals, tower bottoms piping, and reduced crude heat exchanger circuits operating above 500 °F (260 °C).
• Vacuum Distillation Units (VDU): Vacuum furnace fired tubes, vacuum transfer line (where naphthenic acid is not dominant), vacuum tower bottoms circuits, and pitch/resid pumps.
• Delayed Coking Units (DCU): Coker furnace tubes, transfer lines to coke drums, and coker fractionator bottoms circuits.
• Visbreaking Units: Visbreaker furnace coils, soaker drum piping, and residue transfer lines.
• FCC Units: Heavy cycle oil (HCO) circuits, fractionator bottoms slurry pumparounds operating above 500 °F.

2. Physical and Metallurgical Appearance

• Macroscopic Morphology: Metal loss manifests as uniform circumferential wall thinning around the entire 360-degree perimeter of the pipe. The metal surface is covered by a dense to friable, multi-layered, dull black or charcoal-gray iron sulfide ($\text{FeS}$) scale.
• Pyrophoric Hazards During Outages: When iron sulfide scale is exposed to air (oxygen) during unit turnarounds, it undergoes an intense exothermic oxidation reaction: $4\text{FeS} + 7\text{O}_2 \longrightarrow 2\text{Fe}_2\text{O}_3 + 4\text{SO}_2 + \text{Heat}$ This pyrophoric reaction can reach incandescence, igniting residual hydrocarbon vapors. Chemical cleaning (permanganate or nitrate washes) or continuous water misting is required to neutralize pyrophoric scale prior to air entry.

3. Inspection and Non-Destructive Examination (NDE) Protocols

• 100% Component Verification per API 939-C: API RP 939-C guidance is to identify all carbon steel piping circuits operating above 500 °F (260 °C). For lines of unknown metallurgical pedigree, Optical Emission Spectroscopy (OES) or portable spark-PMI must be deployed to quantify exact silicon weight percentages. Any piping component, fitting, or spool piece exhibiting Si < 0.10 wt% must be flagged for prioritized thickness scanning or replacement.
• Profile Radiography (PRT): Essential for small-bore piping, vents, drains, and pipe bends. PRT reveals internal scale thickness and remaining base metal wall thickness without insulation removal.
• Automated Ultrasonic Thickness Scanning (AUT): High-density grid scanning or phased array UT (PAUT) along straight runs and elbows to detect uniform wall thinning and identify localized acceleration.
• Guided Wave Ultrasonic Testing (GWUT): Screening tool for long straight runs of insulated piping to detect significant cross-sectional area loss before conducting targeted UT verification.